DR and Utility Planning

1
DR and Utility Planning

• Tim Roughan
• Director of Distributed Resources
• September 8, 2004

2
Deferral Brockton Pilot

• Looking at potential deferral of a 1.2 million
  upgrade at Belmont St. substation
• Limit load at substation to 45 MW
• Estimate was a need for 900 kWs in 2002
• 1,800 kWs in 2003
• 2,700 kWs in 2004
• Credit based on deferral savings (cost of money
  over 3 years)
• 50 per kWh when we call
• Assumed need for 900 kWs for 50 hours or 45,000
  kWhs - 22,500 of credit

3
Deferral Brockton Pilot

• Marketed to 25 customers over 200 kWs fed from
  substation
• Represented 14 MWs of 45 MW peak load
• 10 of the 25 signed up
• Conducted load shed audits - Measures used
• Hospital planned on EMS upgrade
• Food stores had corporate EMS load control
  already in place
• Industrial customers manually shut down different
  production lines
• Food services vendor brought in ice to keep
  freezers cold

4
Deferral Brockton Pilot

• Had real-time access to substation loads through
  Company EMS
• Provided real-time metering to customers
• Smartsynch / LG meter using Skytel
  communications system
• Results for 2002 - called 4 times
• July 3rd, 23rd, August 13th, 14th
• Total of 17 hours
• Average reduction of 800 kWs, but real success
  was keeping load at substation below ratings.

5
Brockton Pilot Results 2003, 2004

• No calls made in 2003
• Two calls made in 2004 (as tests, no real need)
• August 3rd and August 30th
• Total of 5 hours
• Average load shed only 500 kWs or so.
• Customers need a lot of cajoling and assistance
  to participate
• Less participation than in 2002

6
Niagara Mohawk DG RFP Process

• The NYPSC's Order on DG (Order 01-5) and the
  Merger Rate Plan required Niagara Mohawk to
  identify two projects and issue RFPs.
• RFP was issued in 2002 for planning year 2004.
• Initially, 21 separate companies requested and
  received the RFP package. A pre bid meeting was
  held two weeks after the packages were provided.
  The pre bid meeting was attended by 12
  representatives from 8 companies.
• The RFP's that were issued were for projects that
  would have, if economically viable, deferred the
  installation of a substation, transmission line
  tap and distribution work in both the town of
  Colonie in the Eastern Division and the town of
  Hamburg in the Western Division.

7
The DG Projects

• Hamburg The area of the Town of Hamburg and
  northern Town of Evans along the shore of Lake
  Erie inland needed reinforcement. Approximately
  20 MVA of reinforcement was needed over a five
  year horizon. The first 4 MVA of DG in service
  on May 1, 2004.
• Colonie The area of the Town of Colonie needed
  reinforcement. Approximately 26 MVA of
  reinforcement over a 5 year horizon. The first
  13 MVA of DG in service on June 1, 2004, with 11
  MVA in 2005 and 2 MVA in 2006.

8
The DG Bids

• Hamburg 3 bids were provided by two companies
• Company A provided a proposal and an alternate
  proposal with a cleaner technology. The
  alternate proposal was approximately 25 more
  expensive.
• Company B was unable to meet the required
  availability factors specified in the RFP. The
  feeder availability factor was 99.9795. The
  proposal stated specifically that it would only
  meet 98 on the area aggregate basis.
• Colonie Project 3 bidders provided 4 proposals.
• The alternate bid for Colonie was approximately
  40 higher than the base bid for the cleaner
  technology (natural gas Vs diesel). The
  technical exceptions and problems described above
  for the Hamburg bid also applied to the Colonie
  bid.
• The projects that DG was to offset had project
  estimates between 2.0 million and 2.8 million.
  The annual levelized costs of the projects were
  between 170,000 and 248,000. The DG bids were
  approximately 2 million per year for the 5 year
  trial program. Both TD projects are now
  underway.

9
2004 NM DG RFP

• Issued 9/1/04 substantially higher TD costs
  than previous RFPs
• Amherst area
• Cumulative DG required to be installed
• June 1, 2006 - 31.7 MVA
• June 1, 2007 - 35.7 MVA
• June 1, 2008 - 39.7 MVA
• June 1, 2009 - 41.7 MVA
• Clymer area
• 10 MVA needed by 11/1/06
• Nov thru May run times only

10
Can DG fit into MECos plans?

• May require bulk of revenue stream required to
  pay off project to come from on-site energy sales
• 90-95 of revenue stream on-site energy sales
• 5-10 as localized credits
• Will require utility control of units, or on-site
  load to come off-line if DG trips